The present invention is directed to a downhole tool, and more particularly to a flexible casing guide running tool.
In oil and gas exploration and production operations, bores are drilled to gain access to subsurface hydrocarbon-bearing formations. The bores are typically lined with steel tubing, known as tubing, casing or liner, depending upon diameter, location and function. The tubing is run into the drilled bore from the surface and suspended or secured in the bore by appropriate means, such as a casing or liner hanger. For casing, cement may then be introduced into the annulus between the tubing and the bore wall.
As the tubing is run into the bore, the tubing end will encounter irregularities and restrictions in the bore wall, for example ledges formed where the bore passes between different formations and areas where the bore diameter decreases due to swelling of the surrounding formation. Further, debris may collect in the bore, particularly in highly deviated or horizontal bores. Accordingly, the tubing end may be subject to wear and damage as the tubing is lowered into the bore. These difficulties may be alleviated by providing a ‘shoe’ on the tubing end. Examples of casing shoes of various forms are well known in the art.
Another problem that some drilling engineers have described is the difficulty of running casing through build sections. More specifically, there is difficulty in running large diameter casing through the build section of a well in moderate to so ft formations. The stiffness of the casing requires a significant force that must be generated at the casing shoe to cause the casing to bend to follow the curved section of the wellbore.
In one example, it is necessary to run steel casing with a 16.5 inch outside diameter (OD) and 14.8 inch inside diameter (ID) through a planned wellbore curvature of 1 to 2 deg/100 ft to an inclination of 62 degrees. FEA (finite element analysis) studies can be used to determine the force required to deflect the 16.5 inch steel casing described above through various curved wellbores.
Because wells cannot be drilled exactly as planned, and exhibit some deviation from the planned wellpath, a statistical analysis of similar wells indicates that a planned wellbore curvature of 1 to 2 deg/100 ft will likely result in a maximum measured curvature of 3 to 4 deg/100 ft, with an instantaneous maximum curvature of up to 6 to 8 deg/100 ft in some areas.
FIG. 1 illustrates the results of one of these FEA studies. A plot of the force required to deflect the casing through various curves is shown in FIG. 2.
In the example given above, a force of up to 15,100 lbs could be required to deflect the casing through a maximum curvature condition. This force, when acting through the leading radius of the casing shoe, would generate a large compressive stress on the rock formation, possibly enough to cause the casing to ‘dig in’ to the formation instead to traversing through the curve. Consequently, a need exists to provide a solution against digging into the well formation.